CEQUENCE ENERGY ANNOUNCES 2015 FINANCIAL AND OPERATING RESULTS

Transcription

1 CEQUENCE ENERGY ANNOUNCES 2015 FINANCIAL AND OPERATING RESULTS CALGARY, March 29, 2015 Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, The Company s Consolidated Financial Statements and Management s Discussion and Analysis are available at and on SEDAR at Highlights Highlights for 2015 include: Completed a midstream transaction selling 50% of existing Simonette facilities and related infrastructure to KANATA Energy Group. Substantially completed construction of the shallow cut refrigeration addition at the facility (120 mmcf/d). The refrige facility was commissioned on January 21, 2016 and was completed at approximately 14% under budget. Drilled and completed a highly successful Montney well at W5 utilizing a new completion design. Post tie-in the well has an IP 60 day average production rate of 1,360 boe/d (6.1 mmcf/d and 342 bbl/d of condensate). With a measured depth of 6,100 meters and completed lateral length of 3,050 meters, the completion utilized a 70 stage cemented coil shift frac system. Drilled a Dunvegan oil well at W5. The well has produced a total of 56,000 bbls of 41 API crude since coming on stream August The average calendar day rate since coming on is approximately 260 bbls/d (490 boe/d) flowing. Reduced net 2015 capital expenditures to $18.6 million in an effort to preserve balance sheet flexibility. As at year end, the Company has net debt of $64.5 million comprised of negative working capital of $4.5 million and $60 million of senior notes which mature in October Increased proved reserves by 9 percent from the prior year to 62,513 mboe, with a reserve replacement ratio of 255 percent, based on its independent reserves evaluation effective December 31, Increased proved plus probable reserves by 7 percent from the prior year to 125,983 mboe, with a reserve replacement ratio of 328 percent, based on its independent reserves evaluation effective December 31, 2015.

2 - 2 - Financial and Operating Highlights (000 s except per share and per unit amounts) Three months ended December 31, Twelve months ended December 31, FINANCIAL % Change % Change Production revenue (1) 16,112 25,566 (37) 80, ,893 (41) Comprehensive income (loss) (146,585) (4,422) 3,215 (250,072) 79,368 (415) Per share basic (0.69) (0.02) 3,350 (1.19) 0.38 (413) Per share - diluted (0.69) (0.02) 3,350 (1.19) 0.37 (422) Funds flow from operations (2) 4,874 13,745 (65) 25,578 70,650 (64) Per share, basic (71) (64) Per share, diluted (67) (64) Capital expenditures, before acquisitions (dispositions) 15,175 56,472 (73) 62, ,215 (65) Capital expenditures, including acquisitions (dispositions) 16,351 54,091 (70) 18,560 29,433 (37) Net debt and working capital deficiency (3) (64,452) (71,354) (10) (64,452) (71,354) (10) Weighted average shares outstanding basic 211, , , ,990 - Weighted average shares outstanding - diluted 211, , , ,092 (1) OPERATING Production volumes Natural gas (Mcf/d) 41,794 49,265 (15) 47,589 55,826 (15) Crude oil (bbls/d) Natural gas liquids (bbls/d) (45) (19) Condensate (bbls/d) (17) (1) Total (boe/d) 8,213 9,720 (16) 9,485 10,932 (13) Sales prices Natural gas, including realized hedges ($/Mcf) (26) (28) Crude oil ($/bbl) (32) (45) Natural gas liquids ($/bbl) (45) (59) Condensate ($/bbl) (25) (42) Total ($/boe) (25) (32) Netback ($/boe) Price, including realized hedges (25) (32) Royalties 0.67 (1.25) (154) (0.84) (3.51) (76) Transportation (1.77) (1.48) 20 (1.83) (1.48) 24 Operating costs (9.30) (6.67) 39 (9.17) (7.63) 20 Operating netback (43) (47) General and administrative (2.65) (2.27) 17 (2.30) (2.21) 4 Interest (4) (2.15) (1.87) 15 (1.96) (1.87) 5 Cash netback (59) (59) Notes (1) Production revenue is presented gross of royalties and includes realized gains (loss) on commodity contracts. (2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. (3) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities, demand credit facilities, principal value of senior notes and excluding share based payment liability and provisions. (4) Represents finance costs less amortization on transaction costs and accretion expense on senior notes and provisions.

3 - 3 - Montney Operations The Montney well has performed strongly over its first 60 days. Since being tied into permanent facilities the well has produced at an IP30 rate of 6.6 MMcfd and 403 bbl condensate (1,503 boe/d), and an IP 60 rate of 6.1 mmcfd and 342 bbl/d condensate (1,360 boe/d). This condensate rate is double the historical 5 bcf Simonette forecast model. The free field condensate yield remains at approximately 50 bbls per mmcf. Management believes that the western portion of the Simonette lands have significant additional potential for higher yield Montney using this new drilling and completion technique. The western lands are characterized by lower average gross overriding royalties with 18 sections ranging from 1-2% versus the area average of approximately 5% thereby enhancing the economics of future drilling in this higher liquids area. With the startup of the new refrigeration plant at Simonette in January, Cequence has continued to manage production levels to optimize its existing transportation contract volumes. On April 1, 2016 Cequence commitment on the Alliance system steps down from 55,000 GJ/d to 30,000 GJ/d coincident with the commissioning of the Company s new 200 mmcfd meter station on the NGTL system. Interruptible volumes are now available to Cequence on the NGTL system and the Company expects to be optimizing production through both major pipeline systems through the balance of the year based on current gas prices and by producing its highest netback wells. Simonette Dunvegan Oil Update The W5 Dunvegan well (50% WI) has produced approximately 56,000 bbls of 41 API oil to the end of February at a calendar day rate of approximately 260 bbl/d (490 boe/d). The well continues to exceed the Company s forecast model and is still flowing at approximately 200 bbl of oil per day. The 4-11 offset well (50% WI) was drilled to a lateral length of 3,000 meters and successfully completed with a 47 stage cemented coil shift frac system. During a subsequent cleanout, operational difficulties occurred causing a delay in the cleanup and production of the well. In February, the well averaged 116 bbl oil per day, 182 bbls fluid per day at a 64% oil cut on pump. More than 8,000 m3 of load water remains in the well. A pressure build-up is planned during spring break-up to adequately upsize the pumping system. Cequence is confident in the development plan for the pool with a total potential of 28 wells (24 net wells) at an average lateral length of 1,900 meters.

4 Operational and Production Matters Corporate production for the three and twelve months ended December averaged 8,213 boe/d and 9,485 boe/d, respectively, compared to production of 9,720 boe/d and 10,932 boe/d in Throughout 2015, the Company s production was restricted due to third party pipeline constraints and voluntary shut-ins to avoid high price differentials and to accommodate the Company s gas plant construction. For the three and twelve months ended December 31, 2015, the Company had approximately 2,300 boe/d and 2,600 boe/d of production curtailed. Operating costs averaged $9.17 per boe in 2015 which was up from $7.63 per boe in Additional water handling costs, chemical costs and reduced Simonette production due to the weak pricing environment contributed to the higher unit costs. In addition, midstream fees related to the sale of the plant beginning in June 2015 added to the overall cost of the operation. Simonette operating costs averaged $7.76 per boe while other non-core property costs averaged $18.23 per boe Financial Matters Total production revenue, gross of royalties, was $16.1 million in the fourth quarter of 2015 compared to $25.6 million in The decrease in revenue is attributable to the 25 percent decrease in realized sales prices and 16 percent decrease in production. For the twelve months ended December 31, 2015, production revenue, gross of royalties, decreased 41 percent to $80.9 million from $136.9 million in the comparable period of Natural gas prices remained low throughout 2015 as North American production has been sustained at record high levels while seasonal demand has been lower than expected due to a warm North American winter. Canadian benchmark natural gas prices averaged $2.48 per mcf and $2.71 per mcf for the three and twelve months ended December 31, 2015, respectively, down 32 percent and 40 percent from the same time period in Realized natural gas prices before hedging for the three and twelve months ended December 31, 2015 were $2.16 per mcf and $2.73 per mcf compared to $3.88 per mcf and $4.97 per mcf in the comparable periods of Cequence has hedged approximately 50 percent of expected 2016 natural gas production (net of royalties) at an average price of $2.72/GJ or $2.91/mcf. The fair value of the commodity contracts outstanding at December 31, 2015 was a current asset of $3.6 million. For the twelve months ended December 31, 2015, capital expenditures, excluding acquisitions and dispositions, decreased to $62.2 million from $180.2 million in Consistent with 2014, the Company s 2015 capital expenditures were focused on its Simonette property. Drilling and completion activity was reduced to $26.4 million in 2015 from $127 million in 2014 as Cequence drilled fewer wells is response to lower commodity prices. Equipment, facility and tie-in expenditures of $33.3 million were directed towards facility expansion and gas plant construction at Simonette. On June 17, 2015, Cequence sold a 50% interest in its existing Simonette facilities and related infrastructure, including the facilities

5 - 5 - constructed in Total cash consideration was approximately $41.8 million, including estimated purchase price adjustments and resulted in a gain recognized in comprehensive income (loss) of $5.1 million. Cequence will continue to fund its 50 percent working interest in the gas plant expansion which was completed in the first quarter of During the twelve months ended December 31, 2015, the Company completed additional sales of certain non-producing oil and gas properties for total cash consideration of $3 million ( $153 million), subject to final adjustments. Cequence budgeted net capital expenditures of $22 million for the year ended December 31, 2015 compared to actual expenditures of $18.6 million. Drilling activity was curtailed in the fourth quarter as commodity prices continued to decline. On December 31, 2015, Cequence recorded a $144 million impairment charge related to its Deep Basin and Peace River Arch CGUs. The impairments were a result of a lower outlook for future crude oil and natural gas prices compared to September 30, Commodity prices further deteriorated in the fourth quarter, in particular natural gas prices used in the first three years of the Company s independent reserves evaluator s price forecast decreased by 20 percent, 10 percent and 7 percent, respectively. The impact of lower forecasted benchmark commodity prices was only partially offset by an increase in proved plus probable reserves of 7 percent and the positive impact of lower future development capital. On September 30, 2015, Cequence recorded impairment of $86.4 million related to its Deep Basin, Peace River Arch and Northeast British Columbia CGUs. The impairments were a result of a lower outlook for crude oil and natural gas prices. Additional Matters Cequence has concurrently disseminated a press release dated March 29, 2016 detailing changes to its management team, among other things. About Cequence Cequence is a publicly traded Canadian energy company involved in the acquisition, exploitation, exploration, development and production of natural gas and crude oil in western Canada. Further information about Cequence may be found in its continuous disclosure documents filed with Canadian securities regulators at For further information contact: Todd Brown, CEO, (403) , TBrown@cequence-energy.com David Gillis, Executive VP and CFO, (403) , dgillis@cequence-energy.com Forward-looking Statements or Information Certain statements included in this press release constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as

6 - 6 - "believe", "expect", "plan", "estimate", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this press release may include, but are not limited to, statements or information with respect to; the Company s guidance and forecasts: expected condensate yields; the economics of expected higher yield Montney wells; transportation strategies for optimizing production and the expected results therefrom; expected benefits to be derived from cost savings initiatives; and the expectations for the Dunvegan oil development plan. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties may cause actual results to differ materially from the forward-looking statements or information. The material risk factors affecting the Company and its business are contained in the Company's Annual Information Form which is available on SEDAR at The forward-looking statements or information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this press release are expressly qualified by this cautionary statement. Additional Advisories The press release contains references to terms commonly used in the oil and gas industry. Netback is not defined by IFRS in Canada and is referred to as a non-gaap measure. Netbacks equal total revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze operating performance. Funds flow from operations is a non-gaap term that represents cash flow from operating activities before adjustments for decommissioning liability expenditures, proceeds from the sale of commodity contracts and changes in non-cash working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income (loss) per share. Operating and cash netback is not defined by IFRS in Canada and is referred to as a non-gaap measure. Operating netback equals total revenue less royalties, operating costs and transportation costs. Cash netback equals the operating netback less general and administrative expenses and interest expense. Management utilizes these measures to analyze operating performance. Non-GAAP measures do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.

7 - 7 - BOEs are presented on the basis of one BOE for six Mcf of natural gas. Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. For fiscal 2015, the ratio between the average price of West Texas Intermediate ( WTI ) crude oil at Cushing and NYMEX natural gas was approximately 19:1 ( Value Ratio ). The Value Ratio is obtained using the 2015 WTI average price of $48.68 (US$/Bbl) for crude oil and the 2015 NYMEX average price of $2.63 (US$/MMbtu) for natural gas. This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value. The TSX has neither approved nor disapproved the contents of this news release.